Method for detecting liquid condensation and recovering hydrocarbons

ABSTRACT

A method of improving natural gas recovery from a subterranean hydrocarbon reservoir includes at least one renewable energy source that is electrically coupled with a heat conducting element. The heat conducting element is positioned in a perforated section of a wellbore that traverses into the subterranean hydrocarbon reservoir. A temperature of the subterranean hydrocarbon reservoir is maintained above a cricondentherm temperature so that liquid condensation may be prevented at a final production time. In order to maintain the temperature within a required temperature range, an internal temperature, an internal pressure, and a set of reservoir properties are monitored and then utilized to plot a phase diagram that can be used to detect liquid condensation. If liquid condensation is detected, an electrical output of the renewable energy source is adjusted in order to control the temperature of the subterranean hydrocarbon reservoir at a producing end of a production tubing.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is a Continuation of U.S. application Ser. No.16/665,685, pending, having a filing date of Oct. 28, 2019.

BACKGROUND Field of the Invention

The present disclosure relates to methods of recovering natural gas fromsubterranean hydrocarbon reservoirs. In particular, the presentdisclosure describes a method of using renewable energy as a source ofdownhole heating such that liquid condensation may be prevented andnatural gas recovery may be improved.

Description of the Related Art

Gas condensate is a hydrocarbon liquid stream separated from natural gasand includes higher-molecular-weight hydrocarbons that exist in thereservoir as constituents of natural gas but which are recovered asliquids in separators, field facilities, or gas-processing plants.

Moreover, gas condensate is distinguished by the fluid behavior whenliquid and gas phases coexist as the reservoir pressure drops below adew point. The retrograde behavior, which is a result of multicomponenthydrocarbon molecular interactions, is unfavorable in the overallnatural gas recovery process. As a result of the fluid behavior, liquidtends to accumulate around the wellbore and significantly reduce thereservoir deliverability.

According to recent statistical reviews, natural gas reservoirsincluding gas condensates supply more than a quarter of the globaldemand of energy. Natural gas (also called fossil gas) is a naturallyoccurring hydrocarbon gas mixture entailing primarily of methane, butcommonly including varying amounts of other higher alkanes, andsometimes a small percentage of carbon dioxide, nitrogen, hydrogensulfide, or helium. The composition of the natural gas dictates thebehavior during the production process. Based upon the fractions oflighter hydrocarbons, gas reservoirs are categorized into three groups.Namely, dry, wet, and gas condensate. Among the three groups, gascondensate has the highest fraction of larger alkanes. Gas condensate isproduced as gas in the early stages of production and eventually liquiddrops out as the pressure declines below the dew point. The liquidaccumulation can reach a threshold and restrict the gas inflow and thus,minimize the productivity of the well. The typical phase diagram of gascondensation is shown in FIG. 1.

Gas condensate reservoir performance is closely tied to the phasebehavior which is determined by the chemical compositions, wherein thechemical compositions are determined through experimental and analyticalmethods. See Tu, H.; Guo, P.; Jia, N.; Wang, Z. Numerical evaluation ofphase behavior properties for gas condensate under non-equilibriumconditions. Fuel 2018, 226, 675-685; and Thomas, F. B., Bennion, D. B.,& Andersen, G. (2009, Jul. 1). Gas Condensate Reservoir Performance.Petroleum Society of Canada. doi:10.2118/09-07-18, each incorporatedherein by reference in their entirety. The extent of liquid accumulationis governed by the reservoir pressure, rock permeability, and thefractions of heavy hydrocarbons. See Mott, R. (2003, Oct. 1).Engineering Calculations of Gas-Condensate-Well Productivity. Society ofPetroleum Engineers. doi:10.2118/86298-PA; Raghavan, R., & Jones, J. R.(1996, Aug. 1). Depletion Performance of Gas-Condensate Reservoirs.Society of Petroleum Engineers. doi:10.2118/36352-JPT; and Fevang, Ø., &Whitson, C. H. (1996, Nov. 1). Modeling Gas-Condensate WellDeliverability. Society of Petroleum Engineers. doi:10.2118/30714-PA,each incorporated herein by reference in their entirety. The pressureprofile is lowest at the wellbore and increases with distance to amaximum value at the boundary. As a result, three distinguished regionsof condensate accumulations are created. See Fevang, Ø., Whitson, C. H.,1995. Modeling gas-condensate well deliverability, SPE 30714,incorporated herein by reference in its entirety. In a first region,which is close to the wellbore, the liquid is mobile and hence,significantly reduces the gas relative permeability of the formation. Asecond region of the three regions is below the dew point. However,since the liquid content is insufficient within the second region, aflow is not detected. A third region is partially above the dew pointand only a single phase gas is present. On average, the recovery factorof gas condensate is less than 50% worldwide and can even be low as 10%in some severe cases of liquid accumulation when attempts to restoreproductivity are not successful. See Afidick, D.; Kaczorowski, N. J.;Bette, S. Production Performance of a Retrograde Gas Reservoir: A CaseStudy of the Arun Field. SPE 28749, Presented at SPE Asia Pacific Oiland Gas Conference, Melbourne, Australia, 1994; and Al-Anazi, H. A.;Pope, G. A.; Sharma, M. M. Laboratory measurement of condensate blockingand treatment for both low and high permeability rocks. SPE AnnualTechnical Conference and Exhibition, 2005, each incorporated herein byreference in their entirety.

Maintaining a wellbore pressure above the dew point can prevent theformation of a liquid bank. However, doing so imposes constraints overthe ultimate recovery process. Alternatively, a large pressure drawdowncan be implemented with remedial procedures that are applied to enhancethe well deliverability in continuous shut-in reproduction cycles. Theremedial procedures can be chemical or mechanical. The chemicalprocedures can be divided into two groups, wherein a first group relieson shifting the interfacial tension to enhance the relative permeabilityof gas by injecting weak acidizing organic solvents such as methanol.See Al-Anazi, H. A.; Walker, J. G.; Pope, G. A.; Sharma, M. M.; Hackney,D. F. A successful methanol treatment in a gas-condensate reservoir:field application. SPE Production and Operations Symposium, 2003; Chen,J., Hirasaki, G., Flaum, M., 2004. Study of wettability alteration fromNMR: effect of OBM on wettability and NMR responses, EighthInternational Symposium on Reservoir Wettability, each incorporatedherein by reference in their entirety. The effectiveness of chemicalsolvents is strongly related to the type of the rock, the reservoirheterogeneity, and methanol post-treatment residual saturation. SeeWalker, J. G., 2000. Laboratory Evaluation of Alcohols and Surfactantsto Increase Production from Gas-Condensate Reservoir. The University ofTexas at Austin, Austin, Tex., MS Thesis; and Du, L., Walker, J. G.,Pope, G. A., Sharma, M. M., Wang, P., 2000. Use of solvents to improvethe productivity of gas condensate wells, SPE 62935, each incorporatedherein by reference in their entirety. The methanol post-treatmentresidual saturation would control the long term effect of methanolinjection on the reformation of the condensate bank. A second group,which is determined according to the chemical procedures, relies on theprinciple of increasing the temperature of the accumulated liquid abovea respective vapor phase, wherein the temperature is increased usingexothermic reactions. See Amjed M. Hassan, Mohamed A. Mahmoud, AbdulazizA. Al-Majed, Salaheldin Elkatatny, Ayman R. Al-Nakhli, and Mohammed A.Bataweel; Novel Technique to Eliminate Gas Condensation in GasCondensate Reservoirs Using Thermochemical Fluids, Energy & Fuels 201832 (12), 12843-12850 DOI: 10.1021/acs.energyfuels.8b03604, incorporatedherein by reference in its entirety. Another strategy used for gascondensate related issues is to hydraulically fracture the formationbeyond the liquid bank such that an increase in productivity can beobtained temporarily. However, condensation will occur eventually andaccumulate around the fractured zone. See Sayed, M. A.; Al-Muntasheri,G. A. Mitigation of the effects of condensate banking: a criticalreview. SPE Prod. Oper. 2016, 31, 085-102; Settari, A., Bachman, R. C.,Hovem, K., Paulson, S. G., 1996. Productivity of fractured gascondensate wells—a case study of Smorbukk field, SPE 35604; eachincorporated herein by reference in their entirety. Carbon dioxideinjection has also been investigated to improve the recovery of gascondensate. In particular, increasing the fraction of carbon dioxide inthe reservoir fluid can change the pressure-volume-temperature (PVT)behavior of the fluid. By doing so, a phase envelope, which is a twophase region bounded by the bubble point and the dew point curves, canbe reduced. See Yuan, C.; Zhang, Z.; Liu, K. Assessment of the recoveryand front contrast of CO2 EOR and sequestration in a new gas condensatereservoir by compositional simulation and seismic modeling. Fuel 2015,142, 81-86; Su, Z.; Tang, Y.; Ruan, H.; Wang, Y.; Wei, X. Experimentaland modeling study of CO2—Improved gas recovery in gas condensatereservoir. Petroleum 2017, 3, 87-95; Kossack, C. A., Opdal, S. T., 1986.Recovery of condensate from a heterogeneous reservoir by injection of aslug of methane followed by nitrogen, SPE 18265; and Singer, P.,Hagoort, J., 1998. Recovery of gas condensate by nitrogen injectioncompared with methane injection. SPEJ, 26-33, each incorporated hereinby reference in their entirety. Even though injecting carbon dioxide canbe effective, the procedure may require a large capital investment andclose monitoring of operational managements. The aforementionedprocedures are mainly focused on repair after damage has occurred.Moreover, these procedures are applied throughout the life time of areservoir until production from the reservoir or further treating thereservoir are unfeasible.

Several heating methods for fossil fuel recovery have been developed. Asimplified approach is the in-situ conversion process (ICP), where theheat transfers through a conducting element that is placed in the groundand supplied directly by an electric power source. See J. E. Bridges,“Wind Power Energy Storage for In Situ Shale Oil Recovery With MinimalCO2 Emissions,” IEEE Trans. Energy Convers., vol. 22, no. 1, pp.103-109, 2007, incorporated herein by reference in its entirety.

In view of the difficulties and drawbacks of the existing procedures toimprove subterranean hydrocarbon reservoir performance, it is an objectof the present disclosure to provide a permanent proactive solutionrather than a reactive solution. The method of the present disclosureincludes a minimal interference remedy. In particular, the presentdisclosure includes a method of heat-assisted production of condensatereservoirs especially as it relates to using renewable energy for theheat source.

SUMMARY OF THE INVENTION

The present disclosure describes a method that may be used to improvethe natural gas recovery from subterranean hydrocarbon reservoirs byusing renewable energy sources. In particular, the method of the presentdisclosure describes a method of preventing liquid condensation, whichgenerally hinders the productivity of a subterranean hydrocarbonreservoir, by providing heat generated using renewable energy sources. Aheat conducting element, which is electrically coupled with a renewableenergy source, is positioned in a perforated section within a wellborethat traverses into a subterranean hydrocarbon reservoir. Thus, theenergy generated from the renewable energy source is emitted to thesubterranean hydrocarbon reservoir as heat via the heat conductingelement. The heat emitted from the heat conducting element can becontrolled by manipulating a set of electrical properties of therenewable energy source. An internal reservoir pressure and an internalreservoir temperature, along with a set of reservoir properties of thesubterranean hydrocarbon reservoir are monitored in order to detectliquid condensation. The properties of the renewable energy source areadjusted such that liquid condensation is prevented at the wellbore. Therenewable energy source can be, but is not limited to, solar energy andwind energy.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete appreciation of the invention and many of the attendantadvantages thereof will be readily obtained as the same becomes betterunderstood by reference to the following detailed description whenconsidered in connection with the accompanying drawings, wherein:

FIG. 1 is a gas condensate phase diagram.

FIG. 2 is an illustration of a circuit diagram of a solar cell, whereinthe at least one renewable energy source is solar energy.

FIG. 3A is a flow chart illustrating the method of the presentdisclosure, wherein a process of printing a phase diagram isillustrated.

FIG. 3B is a flow chart illustrating the method of the presentdisclosure, wherein a process of designing a solar panel when the atleast one renewable energy source is solar energy is illustrated.

FIG. 4 is an illustration of a subterranean hydrocarbon reservoirheating system, wherein at least one renewable energy source is used toprovide energy to a downhole electrical heater (DHEH).

FIG. 5 is a phase diagram of a condensate fluid.

FIG. 6 is a graph illustrating the heat propagation inside thesubterranean hydrocarbon reservoir as a function of time at differentlocations from the wellbore.

FIG. 7 is a pressure-temperature profile of the subterranean hydrocarbonreservoir when a heating source is used and when a heating source is notused.

FIG. 8A is a mapping of pressure and temperature of a 6-feet area aroundthe wellbore, wherein temperature and pressure profiles after 10 hoursof production is illustrated.

FIG. 8B is a mapping of pressure and temperature of a 6-feet area aroundthe wellbore, wherein temperature and pressure profiles after 1000 hoursof production is illustrated

FIG. 9 is a heat profile as a function of flow rate at a distance of0.828 feet from the wellbore at 30 hours, 120 hours, 280 hours, and 1000hours.

FIG. 10 is a heat profile as a function of flow rate at a distance of1.5 feet from the wellbore at 30 hours, 120 hours, 280 hours, and 1000hours.

FIG. 11 is a graph illustrating a photovoltaic surface area variation asa function of gas production to maintain a downhole element temperatureat 300-Centigrade (° C.) (572-Fahrenheit (° F.)).

FIG. 12 is a graph illustrating a photovoltaic surface area requirementas a function of the downhole heating temperature for gas production ata flow rate of 0.3 Million standard cubic feet per day (MMSCF/D).

FIG. 13 is a schematic block diagram illustrating a hardwareconfiguration of a phase diagram plotting module associated with a dewpoint determining process of the method of the present disclosure.

FIG. 14 is a schematic block diagram of a data processing systemassociated with the digitizing process of the method of the presentdisclosure.

FIG. 15 is a schematic block diagram illustrating one implementation ofa central processing unit associated with the phase diagram plottingprocess of the method of the present disclosure.

FIG. 16 is a schematic block diagram illustrating the process ofutilizing multiple processors distributed across a network for the phasediagram plotting process.

DETAILED DESCRIPTION

All illustrations of the drawings are for the purpose of describingselected embodiments of the present disclosure and are not intended tolimit the scope of the present disclosure or accompanying claims.

The present disclosure describes using renewable energy resources,primarily solar energy, to provide the energy that generates heat duringa natural gas recovery process. The heat is utilized to avoid liquidcondensation that can hinder the productivity of a subterraneanhydrocarbon reservoir.

When considering the phase diagram of condensate fluid as in FIG. 1,liquid drop out can be avoided at higher temperatures and can also becompletely eliminated above a cricondentherm of the hydrocarbon mixturepresent in the formation, where the cricondentherm is the maximumtemperature above at which a liquid cannot form. The range of hightemperature is generally above the geothermal gradient, wherein thegeothermal gradient is the amount that the temperature of the earthincreases with depth. The geothermal gradient indicates heat flowingfrom a warm interior surface of the earth to the surface. On average,the temperature increases by a temperature within a range of 20Centigrade (° C.)-30° C. for every kilometer of depth.

In regards to applying high temperatures, downhole electrical heaters(DHEH) have shown some success in enhancing the productivity of heavyoil reservoirs. See Bottazzi, F., Repetto, C., Tita, E., & Maugeri, G.(2013, Mar. 26). Downhole Electrical Heating for Heavy Oil EnhancedRecovery: A Successful Application in Offshore Congo. InternationalPetroleum Technology Conference. doi:10.2523/IPTC-16858-Abstract; andCarpenter, C. (2014, Mar. 1). Downhole Electrical Heating for EnhancedHeavy-Oil Recovery. Society of Petroleum Engineers.doi:10.2118/0314-0132-JPT, each incorporated herein by reference intheir entirety. In particular, DHEH is a technique where a heat sourceis placed downhole to increase the near wellbore temperature, which inturn increases the mobility of heavy oils. In a preferred embodiment ofthe method of the present disclosure, an area around the wellbore with aradius within a range of 5 feet (ft)-10 ft is considered, with apreferable radius of 6 ft. A similar approach can be applied to gascondensates to a range where liquid drop out is eliminated.

In in-situ conversion processes (ICP), heat is carried through a thermalconducting material that is placed within a vertical borehole drilledinto a hydrocarbon reservoir. When an alternating current (AC) passesthrough the heaters, an internal temperature of the reservoir will rise.Thus, the recovery of hydrocarbons is improved. At a center point of theheaters, a well area will be designated to receive products from theheated region. When using an alternating current for the purpose ofheating a hydrocarbon-containing geological formation, a surface tovolume ratio of the heated region needs to be minimal to reduce heatlosses to adjacent formations. See G. McQueen, D. Parman, and H.Williams, “Enhanced oil recovery of shallow wells with heavy oil: A casestudy in electro thermal heating of California oil wells,” 2009 Rec.Conf Pap. —Ind Appl. Soc. 56th Annu. Pet. Chem. Ind. Conf. PCIC 2009,2009, incorporated herein by reference in its entirety.

As seen in FIG. 4, the method of the present disclosure for eliminatingliquid accumulation during production of gaseous hydrocarbon from ahydrocarbon-containing geological formation is preferably implementedwith a conceptual reservoir model that comprises a vertical wellbore,wherein the heat conducting element is positioned in a perforatedsection of the vertical wellbore. In particular, the conceptualreservoir model allows a dynamic study of heating during a productionprocess. The subterranean hydrocarbon reservoir is initially above a dewpoint with no flow conditions assumed at the reservoir boundaries. Awellbore pressure is set to a low value to create a gradient for gasflow. At a final production time, where an internal pressure, aninternal temperature, and a set of reservoir properties converge, ameasured wellbore pressure value is approximately half of an initialwellbore pressure value. In addition to the convergence of the internalpressure, the internal temperature, and the set of reservoir properties,at the final production time, a production rate for the subterraneanhydrocarbon reservoir matches a predetermined production rate and liquidcondensation is prevented. Both the measured downhole pressure value,which represents a final pressure value, and the initial downholepressure value are measured within the wellbore. For purposes ofdemonstration, production/flow results related to liquid condensationwere obtained when a heating source was used and also when a heatingsource was not used.

As described earlier, the present disclosure describes a method ofutilizing renewable energy sources for heating purposes during a naturalgas recovery process. To do so, a heat conducting element iselectrically coupled with at least one renewable energy source such thatelectrical energy can be converted into thermal energy. Thus, the energygenerated by the renewable energy source can be transferred into thesubterranean hydrocarbon reservoir as heat through the heat conductingelement. To effectively transfer heat into the subterranean hydrocarbonreservoir, the heat conducting element is positioned in a perforatedsection of a wellbore. In a preferred embodiment, the heat conductingelement is a metal section that can transfer heat into the subterraneanhydrocarbon reservoir through convection and conduction. The metalsection can be made of, but is not limited to, copper, aluminum, brassor bronze. In particular, a metal with a high thermal conductivity valueis preferably used as the heat conducting element. Preferably, the heatconducting element is a portion of iron-based wellbore pipe, e.g.,coiled tubing. The wellbore is in fluid communication with thesubterranean hydrocarbon reservoir. Thus, the natural gas recoveryprocess may be improved due to the heat transferred into thesubterranean hydrocarbon reservoir via the heat conducting element thatis positioned in the perforated section of the wellbore.

In one embodiment, the heat conducting element can be an inductionheating cable, where an outer sheath of the induction heating cable ismade with steel or high temperature fluoroplastic. The induction heatingcable is preferably spliced to allow concentrated heating and to ensureheating is applied to a specific area while protecting the wellbore.Furthermore, the induction heating cable is preferably designed to loweroverall operational costs. Preferably, the induction heating cable willinclude a copper core that is sleeved by a high grade insulationmaterial. The insulation material can be, but is not limited to,crosslinked polyethylene, silicone rubber, ethylene-propyleneelastomers, and thermoplastic elastomers. Both the copper core and thehigh grade insulation will be sleeved by a fiberglass protection.Preferably, a steel armor layer will be used as an outermost layer suchthat the fiberglass protection, the high grade insulation, and thecopper core are all sleeved by the steel armor.

In another embodiment, a current transformer may be used as the heatconducting element such that a primary winding of the currenttransformer can be positioned within a casing at the bottom of thewellbore, wherein a current transformer is a transformer type that isused to reduce or multiply the alternating current. In particular, asecondary winding of the current transformer produces a proportionalelectrical current that is proportional to the electrical currentapplied to the primary winding. A section of the casing functions as asingle turn secondary winding that is positioned adjacent the producingend. Therefore, large induced currents resistively heat the steel of thecasing, and heat is transferred to the formation by thermal conduction.By increasing the frequency of the current at the primary winding, therate of heating can be proportionately increased. In a differentembodiment, the casing, or a section thereof, may be resistively heatedby the flow of large currents in the casing itself. The adjacentformation is heated by thermal conduction from the secondary winding. Inparticular, the secondary winding is in thermal communication with thesubterranean hydrocarbon reservoir. In both inductive heating andresistive heating, the frequency used is generally within a frequencyrange of 55 Hertz (Hz)-65 Hz, with a preferable frequency of 60 Hz.However, if required, higher frequencies can also be utilized.

In a different embodiment, heat can be emitted into the hydrocarbonreservoir through electromagnetic heating. To do so, relative motion iscreated between one or more magnets and a conducting surface, whereinthe conducting surface is the heat conducting element that ismagnetically coupled with at least one magnet. The relative motion,which changes a magnetic field applied to the conducting surface, willinduce eddy currents on the conducting surface. A resistance of theconducting surface will generate heat that is dissipated into thesubterranean hydrocarbon reservoir. In one embodiment, in order toinduce eddy currents in the heat conducting element, the one or moremagnets can be moved in a linear direction with respect to the heatconducting element. In another embodiment, in order to induce eddycurrents in the heat conducting element, either the heat conductingelement or the one or more magnets may be rotated relative to eachother. The heat conducting element and/or the one or more permanentmagnets may be coupled to a pump, positioned within the wellbore, suchthat the reciprocating motion of the pump causes the heat conductingelement and/or the one or more permanent magnets to move in a lineardirection with respect each other. A drive mechanism may be coupled tothe pump, wherein the drive mechanism translates the linear motion ofthe pump into rotational movement of the heat conducting element or themagnets. In a different embodiment, when the one or more permanentmagnets is a plurality of permanent magnets, the plurality of permanentmagnets can be placed in a cylindrical or linear arrangement havingalternately placed north-south poles. The one or more permanent magnetsmay be placed in a linear or cylindrical Halbach array, wherein theHalbach array is a special arrangement of permanent magnets thataugments the magnetic field on one side of the array while cancellingthe field to near zero on the other side which is achieved by having aspatially rotating pattern of magnetization.

In a different embodiment, the heat conducting element may include oneor more electric heating cables, an elongated support member attached tothe heating cables, wherein the elongated support member receives amechanical load from the heating cables, and a cable hang-off configuredto vertically suspend the heating cables and the support member. Thecable hang-off can have a shell through which the heating cables and thesupport member are disposed, the shell having a bowl, and a plurality ofslips that cooperate with each other and with the bowl to form apinching member that grips and suspends the support member. The heatingcables can be mineral insulated cables. The support member can be a wirerope attached to the heating cables at regular intervals with a cablesupport clamp. The cable support clamp can include at least one clampbody having a cable cavity for each heating cable and a rope cavity. Theshell can have a cylindrical mount that receives an end of a length ofthe heat conducting element, and the heating cables and support membercan be disposed within the length of the heat conducting element whenthe support member is suspended by the pinching member. The heatconducting element can be pressure-sealed at an opposite end from theshell, and can be filled with a dielectric fluid.

As described earlier, the heat conducting element is positioned in aperforated wellbore section. A perforation in the context of oil wellsrefers to a hole punched in the casing or liner of an oil well toconnect it to the reservoir. Creating a channel between the pay zone andthe wellbore to cause oil and gas to flow to the wellbore easily,wherein the pay zone is a reservoir or a portion of the reservoir thatcontains economically producible hydrocarbons.

The perforations of the perforated wellbore section can be created usingvarying techniques. All perforating techniques are meant to obtaincommon objective; to have debris free perforations with maximum flowtowards the wellbore. These techniques can include, but are not limitedto, underbalance perforation, dynamic underbalance perforation, andoverbalance perforation.

Underbalance is defined as the amount of pressure exerted on a formationexposed in a wellbore below the internal fluid pressure of thatformation. If sufficient porosity and permeability exist, formationfluids enter the wellbore. The drilling rate typically increases as anunderbalanced condition is approached. On the other hand, overbalance isdefined as the amount of pressure (or force per unit area) in thewellbore that exceeds the pressure of fluids in the formation. Theexcess pressure is needed to prevent reservoir fluids (oil, gas, water)from entering the wellbore.

In underbalance perforation, the wellbore pressure, before perforation,is kept less than the formation reservoir pressure. As a result, withhigh permeability, the initial fluid influx in the tunnel helps inbreaking the crushed zone loose and taking it out from the tunnel intothe wellbore. As the reservoir pressure equalizes with bottomholepressure, the rate of clean up decreases throughout the total number ofperforations. Therefore, complete cleanup is based on the assumptionthat the wellbore pressure remains constant during perforation andcleanup process.

Dynamic underbalance perforating is a perforation technique in which arapid underbalance is created during perforation, and helps in improvingthe optimal flow rate and the effective cleanup of the perforations.During conventional static underbalance perforation, the wellborepressure fluctuates for a fraction of a second due to a high pressurewave generated by the detonation of the shaped charges. The pressurewave, reducing the rock mechanical strength, propagates through the rockmatrix with a high variation of wellbore pressure forming the desiredperforation tunnel. The high pressure wave causes the rock matrix toundergo tensile or shear failure around the perforation tunnel. Shearfailure occurs when the tangential or hoop stress at the perforationwall reduces the material strength. The pressure gradient near theinternal walls of the perforation becomes negative (due to thegeneration of underbalance pressure) and high enough, to exceed thetensile strength of the material, tensile failure occurs. Therefore porepressure decreases, decompressing the reservoir fluid around theperforation wall and the present drawdown between the wellbore andreservoir pressure, allows the reservoir fluid to flow into the tunnel.The sudden reservoir fluid flow generated by the wellbore pressure lessthan the reservoir pressure is known as surge flow which causes theloose/weakened particles due to the rock failure and the charge debrisin the tunnel to be displaced into the wellbore, cleaning theperforation tunnel.

Extreme Overbalanced (EOB) perforation is defined as applying a highwellbore pressure above the reservoir pressure during the perforatingprocess or to existing perforations which is also known as EOB surging.The high overbalance which is significantly greater than the formationfracture point (FFP) initiates one or more small fractures around theperforated tunnel, and the fractures intersect with a network offractures and allows more formation fluid into the tunnels.

The heat conducting element can be positioned in the perforated sectiondifferently in embodiments of the present disclosure. In one embodiment,the heat conducting element can be positioned in the perforated sectionwith a protector that can be, but is not limited to, a mid-joint clamp,a cross coupling protector, and a low profile protector. The mid-jointclamp uses a compressive fit design to accommodate oversize orundersized tubing per API specifications and securely engages the cableor lines extending to the heat conducting element to the tubing. Fieldinstallation is quick and simple using our air driven hydraulicinstallation tools to compress the collars. The cross coupling protectoruses a channel to shield cables or lines as they transition across thecoupling to prevent damage during installation or retrieval ofcompletions. The low profile protector uses a “compressive wave” designand as a result has a tighter tolerance range on the tubing string. Thelow profile protectors use channels to shield cables or lines as theytransition across the coupling to prevent damage during installation orretrieval of completions.

The cross coupling protectors and the mid-joint clamps can be configuredto be used with tubes that have an outer diameter within a range of 1.0inches (in)-14.0 in, with a preferable range of 2.0 in-13.75 in. Themid-joint clamp and the cross coupling protector can be, but is notlimited to, a bolt-up type and a pin-up type. Furthermore, the mid-jointclamp and the cross coupling protector can be, but is not limited to,being made of carbon steel or stainless steel casting bodies. Air drivenhydraulic installation tools may be utilized when positioning the heatconducting element with the mid-joint clamps or the cross couplingprotectors.

The heating element is preferably placed in direct contact with therock. The heating element is perforated to allow for gas and hydrocarbonproduction. In one embodiment the heating element is a resistive heatingelement that is embedded in the matrix of the pipe that is perforated.As such when the pipe/tubing is perforated the heating element isconcurrently perforated.

The heat transferred to the subterranean hydrocarbon reservoir ismanaged by applying an electrical current to a liquid condensationprevention system, wherein the electrical current is generated from atleast one renewable energy source. The liquid condensation preventionsystem comprises the heat conducting element which is positioned in thewellbore located in the subterranean hydrocarbon reservoir. To utilizeheat to improve a production rate of the subterranean hydrocarbonreservoir, the heat conducting element is connected to a producing enddisposed in the subterranean hydrocarbon reservoir. Moreover, a recoveryend is located outside the wellbore such that the production tubing isconfigured to pass gaseous natural gas resulting from the productionprocess from the producing end of the production tubing, which ispositioned within the subterranean hydrocarbon reservoir, to therecovery end of the production tubing, which is positioned outside thewellbore.

Since the heat conducting element is electrically coupled with the atleast one renewable energy source, the heat emitted by the heatconducting element can be controlled by manipulating a set of energysource parameters which impacts the electrical output of the at leastone renewable energy source. More specifically, the electrical outputfrom the at least one renewable energy source affects the heatingcapabilities of the heat conducting element. If a solar cell is usedwhen the at least one renewable energy source is solar energy, the setof energy source parameters can include, but is not limited to, anoverall solar cell surface area, a voltage imposed across the solarcell, a photogenerated current, a parallel resistance, and a seriesresistance. Since the heat conducting element is in thermalcommunication with the subterranean hydrocarbon reservoir, the heatemitted from the heat conducting element impacts the overall phasebehavior within the subterranean hydrocarbon reservoir since phasebehavior is dependent on the temperature and the pressure within thesubterranean hydrocarbon reservoir.

When the at least one renewable energy source is solar energy, the typeof solar cell used to implement the method of the present disclosure canvary in different embodiments. The type of solar cell can be, but is notlimited to, an amorphous Silicon solar cell (a-Si), a biohybrid solarcell, a cadmium telluride solar cell (CdTe), a concentrated photovoltaic(PV) cell (CVP), Copper indium gallium selenide solar cells (CI(G)S), acrystalline silicon solar cell (c-Si), a dye-sensitized solar cell(DSSC), a Gallium arsenide germanium solar cell (GaAs), a hybrid solarcell, a luminescent solar concentrator cell (LSC), a micromorph(tandem-cell using a-Si/μc-Si), a monocrystalline solar cell (mono-Si),a multi-junction solar cell (MJ), a nanocrystal solar cell, an organicsolar cell (OPV), a Perovskite solar cell, a photoelectrochemical cell(PEC), a plasmonic solar cell, a polycrystalline solar cell (multi-Si),a Quantum dot solar cell, a solid-state solar cell, thin-film solar cell(TFSC), a wafer solar cell, or a wafer-based solar cell crystalline.

Amorphous silicon (a-Si) is the non-crystalline form of silicon used forsolar cells and thin-film transistors in liquid crystal displays. Usedas semiconductor material for a-Si solar cells, or thin-film siliconsolar cells, it is deposited in thin films onto a variety of flexiblesubstrates, such as glass, metal and plastic. Amorphous silicon cellsgenerally feature low efficiency, but are one of the mostenvironmentally friendly photovoltaic technologies, since they do notuse any toxic heavy metals such as cadmium or lead.

A biohybrid solar cell is a solar cell made using a combination oforganic matter (photosystem I) and inorganic matter, wherein photosystemI (PSI, or plastocyanin-ferredoxin oxidoreductase) is the secondphotosystem in the photosynthetic light reactions of algae, plants, andsome bacteria. PSI is used to recreate the natural process ofphotosynthesis to obtain a greater efficiency in solar energyconversion.

Cadmium telluride (CdTe) photovoltaics describes a photovoltaic (PV)technology that is based on the use of cadmium telluride, a thinsemiconductor layer designed to absorb and convert sunlight intoelectricity. Cadmium telluride PV is the only thin film technology withlower costs than conventional solar cells made of crystalline silicon inmulti-kilowatt systems.

Concentrator photovoltaics (CPV) (also known as concentrationphotovoltaics) is a photovoltaic technology that generates electricityfrom sunlight. Unlike conventional photovoltaic systems, it uses lensesor curved mirrors to focus sunlight onto small, highly efficient,multi-junction (MJ) solar cells. In addition, CPV systems often usesolar trackers and sometimes a cooling system to further increase theirefficiency.

A copper indium gallium selenide solar cell (or CIGS cell, sometimesCI(G)S or CIS cell) is a thin-film solar cell used to convert sunlightinto electric power. It is manufactured by depositing a thin layer ofcopper, indium, gallium and selenium on glass or plastic backing, alongwith electrodes on the front and back to collect current. Because thematerial has a high absorption coefficient and strongly absorbssunlight, a much thinner film is required than of other semiconductormaterials.

In order to monitor a phase behavior throughout a natural gas productionspan, temperature and pressure distribution are mapped for each gridblock of a plurality of grid blocks, wherein the plurality of gridblocks spans across the subterranean hydrocarbon reservoir. Theplurality of grid blocks is used to turn the geological model of thesubterranean hydrocarbon reservoir into a discrete system on which fluidflow equations can be solved. The plurality of grids is determinedaccording to the type of fluid displacement or depletion processmodelled, past and anticipated field development, desired numericalaccuracy, available software options, objectives of the simulationstudy, and other factors such as computer resources and timeconstraints. Cartesian and cylindrical are some of the common gridcoordinate systems. The Cartesian coordinate system generates a3-dimensional grid. Cylindrical coordinate systems, which use a radialsystem, are beneficial for near well studies dominated by radial inflow.

In the process of mapping temperature and pressure distribution, aninternal pressure of the subterranean hydrocarbon reservoir, an internalpressure of the subterranean hydrocarbon reservoir, and a set ofreservoir properties within the subterranean hydrocarbon reservoir areiteratively solved for convergence for a corresponding time step of aplurality of time steps, wherein the plurality of time steps representsthe production span of the subterranean hydrocarbon reservoir. The setof reservoir properties can be, but is not limited to, a wellborepressure, natural gas viscosity, a gas compressibility factor, thicknessof the pay zone, subterranean hydrocarbon reservoir radius, heatcapacity, rock density, gas density, thermal expansion factor, andthermal conductivity.

When solving for convergence, the corresponding time step is incrementedto a subsequent time step of the plurality of time steps, if theinternal pressure, the internal temperature, and the set of reservoirproperties do not converge. At convergence, the internal pressure, theinternal temperature, and the set of hydrocarbon properties aremonitored, and the corresponding time step at convergence is identifiedas the final production time if the predetermined production rate isobtained. The final production time is dependent on an overall size ofthe subterranean hydrocarbon reservoir and a production rate of thesubterranean hydrocarbon reservoir. Thus, the final production time canvary in different embodiments. In a preferred embodiment, the finalproduction time is within a time range that can be, but is not limitedto, 500 hours (hrs)-2000 hrs, 500 hrs-1750 hrs, with a preferable timerange of 1000 hrs-1500 hrs. In particular, the internal temperature, theinternal pressure, and the set of reservoir properties converge and thedesired production rate is obtained within the time range of 1000hrs-1500 hrs.

At convergence for the internal pressure, the internal temperature, andthe set of hydrocarbon properties, and when the predetermined productionrate is obtained, the method of the present disclosure searches forliquid condensation at the wellbore.

In a preferred embodiment of the present disclosure, in a process ofdetecting liquid condensation, the internal pressure and the internalpressure for each of the plurality of time steps is recorded. Next, asseen in FIG. 3A, in the process of detecting liquid condensation, aphase diagram is plotted using the internal temperature and the internalpressure for each of the plurality of time steps up to dew point. Sinceliquid condensation can be prevented by maintaining the internaltemperature and the internal pressure above the dew point, the dew pointcan be used as a reference point in detecting liquid condensation. Ifliquid condensation is detected at the final production, the electriccurrent applied to a liquid condensation prevention system is adjustedto heat the heat conducting element as required. The electric currentcan be adjusted by managing the at the at least one renewable energysource. In a preferred embodiment, a cubic-plus-association (CPA)equation of state is used to plot the phase diagram. However, in otherembodiments of the present disclosure Van der Waals equation of state,Peng-Robinson equation of state, Peng-Robinson-Stryjek-Vera equations ofstate, and Elliott, Suresh, Donohue equation of state may be used.

As seen in FIG. 3B, if liquid condensation is discovered, the heatemitted from the heat conducting element may be adjusted by manipulatingthe set of energy source parameters of the at least one renewable energysource. FIG. 5 is a phase diagram for the condensate fluid at differenttemperature values and different pressure values. A composition of thegas condensate is provided in the following table 1.

Component Mole Fraction N₂ 0.0300-0.0350 H₂S 0.0045-0.0060 CO₂0.0160-0.0180 C₁ 0.8320-0.8340 C₂ 0.0510-0.0520 C₃ 0.0185-0.0200 n-C₄0.0065-0.0075 i-C₄ 0.0035-0.0045 n-C₅ 0.0025-0.0035 Where: N-Nitrogen;H₂S-Hydrogen Sulfide; CO₂-Carbon Dioxide; C₁-Methane; C₂-Ethane;C₃-Propane; n-C₄-Normal Butane; i-C₄-Isobutane; n-C₅-Normal Pentane;

In a preferred embodiment of the method of the present disclosure, theelectrical current is applied such that a temperature of thesubterranean hydrocarbon reservoir at the producing end of theproduction tubing remains above a cricondentherm temperature of thenatural gas, where the cricondentherm is the maximum temperature aboveat which a liquid cannot form. The cricondentherm, which is a propertyof the chemical composition of the gas condensate, can also be definedas the maximum temperature above which liquid cannot be formedregardless of the pressure. The cricondentherm temperature is determinedthrough an equation of state such as the cubic-plus-association (CPA).In a preferred embodiment, the cricondentherm temperature isapproximately within a range of 300 Fahrenheit (° F.)-500° F., 350°F.-400° F., 325° F.-400° F., with a preferable temperature ofapproximately 350° F. Preferably, the temperature of the subterraneanhydrocarbon reservoir at the producing end will be greater than acricondentherm temperature of the gas composition in the geologicalformation by a temperature within a range of 50° F.-200° F., 75° F.-200°F., preferably 100° F.-150° F. greater than a cricondenthermtemperature. By having the temperature at the producing end to begreater than the cricondentherm temperature, liquid condensation may beprevented. In a preferred embodiment, the temperature of thesubterranean hydrocarbon reservoir at the producing end will be within arange of 450° F.-600° F., 500° F.-600° F., with a preferred averagetemperature of approximately 572° F. The heat propagation from the heatconducting element is controlled by the thermal properties of a rockformation within the subterranean hydrocarbon reservoir and fluidswithin the subterranean hydrocarbon reservoir. In a preferredembodiment, a heat loss from the heat conducting element to adjacentrock formations is considered to be negligible and as described earlier,the heat is transferred via conduction and convection. Additionally,heat emitted from a produced fluid may also affect the overall heatpropagation from the heat conducting element.

A maximum efficiency of the subterranean hydrocarbon reservoir isachieved when the wellbore is heated under shut-in conditions.Generally, a reservoir is shut-in for well control purposes and thereservoir stops producing. The efficiency of the method of the presentdisclosure is measured by the extent of heat propagation, wherein theheat propagates from the heat conducting element to the rock formation.During natural gas production, the produced natural gas acts as abarrier of heat propagation as molecules travel in the oppositedirection of heat transfer. In particular, the produced gas travelstowards the wellbore and the heat from the heat conducting elementpropagates away from the wellbore. Convection at certain gas velocitiescan balance the conduction which limits the overall heat propagation.Exemplary gas velocities are shown in FIG. 9.

During natural gas recovery, three phases are generally performed.Namely, drilling with drill pipes, lining with casing, and productionwith tubing. When drilling with drill pipes, durable steel pipes thatconduct the force onto a drill bit are used, and in many cases the drillpipe turns the drill bit. As a result, the drill bit cuts into the rockuntil deposits are reached. The last drill pipes before the drill bitare often nonmagnetic drill collars, especially in horizontal drilling.A drill collar is a component of the drill string that makes up part ofthe bottom hole assembly and are thicker-walled, heavier, and more rigidthan drill pipes and are primarily used to weigh down the drill bitwhile dampening vibration and impact forces. Drill pipe grades includestandard API grades (E-75, X-95, G-105, & S-135), as well as proprietarygrades. The proprietary grades often exceed the specifications set forthby API SPEC 5DP, wherein API SPEC 5DP specifies the technical deliveryconditions for steel drill-pipes with upset pipe-body ends and weld-ontool joints for use in drilling and production operations in petroleumand natural gas industries for three product specification levels(PSL-1, PSL-2 and PSL-3). PS-1 specifies wall thickness, impactstrength, and yield strength requirements specific to the materialgrade. Specification levels PL-2/PL-3 have additional mandatoryrequirements.

The proprietary grades are developed for enhanced performance in sourservice, critical service, and other user-defined requirements. Sourservice grades resist sulfide stress corrosion (SSC). SSC can occur whenhydrogen sulfide is present. Ingress of hydrogen coupled with higherstresses, low temperatures, low pH, and high chloride content decreasesthe ductility of steel grades leaving them susceptible to crackpropagation and failure. Critical service grades resist corrosion whensweet gas or high concentrations of carbon dioxide are present, and alsoprovide a cost effective alternative that is used in water injectionapplications.

The mud in contact with the drill bit cools the drill bit and carriesthe rock cuttings i.e. the cut rock back to the surface. The drill pipeused with the method of the present disclosure can be, but is notlimited to, a standard drill type or a heavy weight drill pipe (HWDP).

Standard drill pipes are long tubular sections of pipe that make up themajority of the drill string. Each drill pipe is generally a 31 footlong section of tubular pipe but may be anywhere from 18 to 45 feet inlength.

Heavy weight drill pipe (HWDP) is a tubular pipe that adds weight oracts as a transitional piece in the drill string. As a transitionalsection of the drill string, it is placed between the drill collar andstandard drill pipe to reduce fatigue failures. In other applications,the HWDP is used as an additional weight to weigh down the drill string.

In a second phase, a wellbore lining process is performed. Inparticular, the lining process is performed with an outer tube which isreferred to as the casing. Casing lines the wellbore and thus, protectsthe layers of soil and above all the groundwater from being contaminatedby the drilling mud and/or fracking fluids. Lining also stabilizes thewellbore, so casing must be able to withstand especially high loads. Thedrilling and casing alternate—the drill string is taken out at specificintervals and the wellbore is lined with casing and cemented. Thedrilling continues after the cementing process. The casing type used canbe, but is not limited to, conductor casing, surface casing,intermediate casing, production casing, liner, and liner tieback casing.

Conductor casing is set below the structural casing (i.e., drive pipe ormarine conductor run to protect loose near-surface formations and toenable circulation of drilling fluid). The conductor isolatesunconsolidated formations and water sands and protects against shallowgas. In general, the conductor casing is the casing string onto which acasing head is installed, wherein the casing string is long section ofconnected oilfield pipe that is lowered into a wellbore and cemented.

Surface casing is set to provide blowout protection, isolate watersands, and prevent lost circulation. Surface casing also often providesadequate shoe strength to drill into high-pressure transition zones,wherein show strength is the maximum pressure the wellbore can withstandwith regard to the casing setting depth. In deviated wells, the surfacecasing may cover the build section to prevent keyseating of theformation during deeper drilling, wherein keyseating is a small diameterchannel worn into the side of a larger diameter wellbore that can resultin a change of direction of the wellbore. The surface casing string istypically cemented to the surface or to the mudline in offshore wells.

Intermediate casing is set to isolate unstable hole sections,lost-circulation zones, low pressure zones, and production zones.Intermediate casing is generally used in the transition zone from normalto abnormal pressure. A cement top of the intermediate casing is used toisolate any hydrocarbon zones.

Production casing is used to isolate production zones and containformation pressures in the event of a tubing leak. Production casing mayalso be exposed to injection pressures from fracture jobs, gas lifts,and the injection of inhibitor oil. Gas lift is an artificial-liftmethod in which gas is injected into the production tubing to reduce thehydrostatic pressure of the fluid column.

Liner is a casing string that does not extend back to the wellhead, butis hung from another casing string. Liners are generally used instead offull casing strings to reduce cost, improve hydraulic performance whendrilling deeper, allow the use of larger tubing above the liner top, andnot represent a tension limitation for a rig.

Liner tieback is a casing string that provides additional pressureintegrity from the liner top to the wellhead. An intermediate tieback isused to isolate a casing string that cannot withstand possible pressureloads, usually because of excessive wear or higher than anticipatedpressures, if drilling is continued. Similarly, a production tiebackisolates an intermediate string from production loads. Tiebacks can beun-cemented or partially cemented.

The production with tubing is the third phase associated with wellboredevelopment. In this phase, tubing transports the oil and gas from deepin the well to the surface. Oil and gas occasionally rise to the surfacewithout assistance. However, pumps are usually used to bring the fluidsto the surface. When selecting the type of tubing, American PetroleumInstitute (API) and International Organization for Standardization (ISO)standards are followed. In particular, API tubes having an outerdiameter within a range of 1.050 inches-4.5 inches is preferablyselected during the production process. For high-rate wells, tubing withan outer diameter larger than 4.5 inches may be used. Preferably, APIsteel is used. However, based on well conditions different tubingmaterial that can be, but is not limited to, corrosion-resistant alloy(CRA) and thermoplastic tubing may be used.

When the wellbore is heated during shut-in conditions, as shown in FIG.6, simulations for the heat emitted from the heat conducting elementrevealed that the cricondentherm temperature can be achieved up to adistance that may be within a range of 0.5 feet (ft)-2.5 ft and 1.25ft-2.0 ft with an average range of approximately 1.5 ft from thewellbore. The heat propagation during the shut-in reveals that shut-inheating is an effective method that may be used to remove condensatebuildup from damaged subterranean hydrocarbon reservoirs.

In contrast to shut-in conditions, when the wellbore is heated during anatural gas production process and when a drawdown pressure is within arange of 50 pounds per square inch (psi)-200 psi, 75 psi-150 psi with apreferable drawdown pressure of 100 psi, the subterranean hydrocarbonreservoir is depleted. More specifically, a drawdown pressure is adifference between a reservoir pressure and a wellbore pressure. In thisinstance, phase behavior is monitored as a function of distance from thewellbore. As shown in FIG. 7, temperature and a pressure at each gridblock from the plurality of grid blocks is monitored and plotted untilpseudosteady state is reached. Pseudosteady state flow is defined as aflow condition under which the pressure at any point in the reservoirdeclines at the same constant rate over time. Pseudosteady state occurswhen there is boundary-dominated flow and the transient period ends. Theboundary-dominated flow is a flow regime that starts when the drainageradius of the well reaches the reservoir boundaries. Boundary-dominatedflow is a late-time flow behavior when the reservoir is in a state ofpseudoequilibrium. As seen in FIG. 8A and FIG. 8B, temperature in anarea adjacent the wellbore gradually increases as the pressure decreasessuch that a two phase region is avoided. In particular, in FIG. 8A, thetemperature is low and the pressure is high in an area 6 ft from thewellbore after 10 hrs of production. In FIG. 8B, the temperature hasrisen and the pressure has lowered in the same 6 ft area around thewellbore after 1000 hrs of production. On the other hand, when heat isnot provided by the heat conducting element, liquid condensation isdetected around the wellbore.

In the subterranean hydrocarbon reservoir, the internal temperature, theinternal pressure, and the set of reservoir properties areinterdependent. Therefore, as described earlier, along with the internaltemperature and the internal pressure, the set of reservoir propertiesis also iteratively solved for convergence. The set of reservoirproperties can be, but is not limited to, the properties listed in table2.

TABLE 2 Reservoir properties Parameter Value P_(i) (pounds per squareinch (psi)) 4900-5100 P_(w) (psi)  75-125 T_(i) (Fahrenheit (° F.))175-200 T_(s) (° F.) 450-600 μ (centipoise (cP)) f1 (P,T) z f2 (P,T)r_(R) (feet (ft))  75-125 h_(pay) (ft)  75-125 ρ_(rock) (Gram per cubiccentimeter (g/cc)) 2.5-3.0 ∅ 0.08-0.2  k (Millidarcy (mD)) 0.08-0.2 Where: P_(i)-Internal pressure of the subterranean hydrocarbonreservoir; P_(w)-Wellbore pressure; T_(i)-Internal temperature of thesubterranean hydrocarbon reservoir; T_(s)-Operating temperature of theheat conducting element; μ-Natural gas viscosity; z-Gas compressibilityfactor; h_(pay)-Thickness of pay zone; r_(R)-Subterranean hydrocarbonreservoir radius; c_(g)-Gas compressibility; c_(t)-Totalcompressibility; C_(p)-Heat capacity (Joule per gram (J/g);ρ_(rock)-Rock density; ρ_(gas)-Gas density; β_(T)-Thermal expansionfactor (1/Kelvin (1/K)); κ-Thermal conductivity (watt per meter kelvin(W/m · K)); ∅-Porosity; k-Permeability (mD);

The heat propagation is analyzed with the reservoir properties of table2, wherein a heat profile is analyzed at a predetermined distance fromthe wellbore as a function of flow rate at different time intervals. Theflow rate is the volume of gas that passes a particular point during aparticular period of time. FIG. 9 is a heat profile as a function of theflow rate at a distance of 0.828 ft from the wellbore, wherein the heatprofile is generated at 30 hrs, 120 hrs, 280 hrs, and 1000 hrsS. FIG. 10is a heat profile as a function of the flow rate at a distance of 1.5 ftfrom the wellbore, wherein the heat profile is generated at 30 hrs, 120hrs, 280 hrs, and 1000 hrs. From FIG. 9 and FIG. 10, a correlationbetween the heat propagation and the flow rate can be seen. Inparticular, as the flow rate exceeds 0.5 Million standard cubic feet perday (MMSCF/D) of gas flow (500,000 Standard cubic feet per day (SCF/D)),the heating efficiency drops significantly indicating convectioncontrolled heat transfer of the produced fluids.

In a preferred embodiment, solar energy is used as the at least onerenewable energy source and a solar cell is used to generate heat thatis eventually emitted from the heat conducting element. Even thoughsolar energy is utilized in a preferred embodiment, in anotherembodiment, wind energy, energy from biomass, and hydropower may be usedas the at least one renewable energy source.

In order to have a complete model that expresses the process oftransforming solar energy into heat, the solar energy model needs to beanalyzed from the solar cell to the point where electrical energy isused for heating purposes. In the process of designing a powergeneration system with renewable energy sources, the intermittencyassociated with renewable energy sources need to be addressed as well.

A surface area of the solar cell is dependent on a temperature requiredat the wellbore and a production rate of the subterranean hydrocarbonreservoir. As seen in FIG. 11, the surface area of the solar cellincreases with the production rate. Furthermore, as seen in FIG. 12, thesurface area of the solar cell increases with the temperature requiredat the wellbore. In particular, for higher temperatures to be generatedat the wellbore, the heat conducting element, which provides heat at thewellbore, needs to receive a higher electrical load from the at leastone renewable energy source. In a preferred embodiment, when the atleast one renewable source is solar energy and a solar cell is utilizedto generate the electrical output required by the heat conductingelement, the surface area of the solar cell is increased. Since thetotal electrical output of the solar cell has a linear relationship withthe surface area of the solar cell, increasing the surface area of thesolar cell can generate the required electrical output. By adjusting thesurface area, the temperature of the subterranean hydrocarbon reservoirat the producing end can be maintained to be higher than thecricondentherm temperatures such that liquid condensation may beavoided. Thus, the overall production rate can be affected by designingthe solar cell according to the energy demands within the wellbore.

Several methods can be used to model a solar cell. These models varyfrom being basic for quick and easy estimation of output power to verydetailed and complicated models that evaluate the amount of energyproduced by a photovoltaic (PV) panel. FIG. 2 is an example of a primarysolar cell topology. See M. G. Villalva, J. R. Gazoli, and E. R. Filho,“Comprehensive approach to modeling and simulation of photovoltaicarrays,” IEEE Transactions on Power Electronics, vol. 24, no. 5, pp.1198-1208, 2009, incorporated herein by reference in its entirety.

$\begin{matrix}{I = {I_{ph} - I_{D} - I_{p}}} & (1) \\{I_{D} = {{I_{0}\lbrack {{\exp( \frac{q( {V + {IR}_{s}} )}{kT_{c}} )} - 1} \rbrack} - I_{D} - I_{p}}} & (2) \\{I_{p} = \frac{V + {IR}_{s}}{R_{p}}} & (3)\end{matrix}$Where:k—Boltzmann's gas constant=1.381×10²³ Joules per kelvin (J/K);T_(c)—Absolute temperature of the solar cell (kelvin);q—Electronic charge=1.602×10¹⁹ Joule/Volt (J/V);V—Voltage imposed across the solar cell;I₀—Saturation current;I_(D)—Dark saturation current, wherein the dark saturation current isdependent on temperature;I_(ph)—Photogenerated current;R_(P)—Parallel resistance in ohms (Ω);R_(S)—Series resistance (Ω);

Equations 1-3 were adjusted under two assumptions. A first assumption isthat the shunt resistance is higher than a load resistance. A secondassumptions is that the series resistance is considerably smaller thanthe load resistance. Thus, the load resistance and the series resistancecan be considered to be negligible such that:

$\begin{matrix}{I = {I_{0}\lbrack {{\exp( \frac{qV}{kT_{c}} )} - 1} \rbrack}} & (4)\end{matrix}$See S. Kalogirou, Solar Energy Engineering: Processes and Systems.Elsevier Science, 2013; and J. Duffie and W. Beckman, Solar Engineeringof Thermal Processes. Wiley, 2013, each incorporated herein by referencein their entirety.

The PV panel provides the short circuit current, the open circuitvoltage, the maximum current, the maximum voltage, and the power, whicheventually helps in circulating the generated total electric directcurrent (DC) power to supply heating elements.

When considering resistances, the parallel resistance, R_(p), functionsindependent to the temperature. However, the parallel resistance behavesinverse to the solar radiation when configured as in FIG. 2.

$\begin{matrix}{R_{p} = {R_{pref}\frac{G_{ref}}{G}}} & (5)\end{matrix}$

The solar cell temperature is represented by equation 6:

$\begin{matrix}{T_{c} = {T_{A} + {( \frac{{NOCT} - {20}}{0.8} )G_{T}}}} & (6)\end{matrix}$See R. Messenger and A. Abtahi, Photovoltaic Systems Engineering, ThirdEdition. CRC Press, 2010, incorporated herein by reference in itsentirety.Where:NOCT—Nominal operation cell temperature;G_(ref)—Reference solar irradiance (Watt/square meter (W/m²));G_(T)—Solar irradiance;R_(pref)—Reference parallel resistance under standard referenceconditions;T_(A)—Ambient temperature (Centigrade (° C.);T_(c)—Solar cell temperature (° C.);In a preferred embodiment,T_(A)=20° C.;G_(T)=800 W/m²;Air mass=1.5;Wind speed<1.5 meters/second (m/s);

As a part of subsurface modelling, reservoir and wellbore temperaturemodelling have been investigated for a considerable time. Informationextracted from such modelling processes is important to understand thefluid behavior during natural gas production process, injection, andreservoir shut-in processes. In a wellbore, temperature modelling andmeasurements can be used to determine factors that can be, but are notlimited to, production locations, fracture heights, and transversefracture numbers and locations. See Kunz, K. S. and Tixier, M. P. 1955.Temperature Surveys in Gas Producing Wells. SPE-472-G; Dawkrajai, P.,Lake, L. W., Yoshioka, K. et al. 2006. Detection of Water or Gas Entriesin Horizontal Wells from Temperature Profiles. Presented at the SPE/DOESymposium on Improved Oil Recovery, Tulsa, 22-26 April. SPE-100050-MS.https://doi.org/10.2118/100050-MS; Yoshioka, K., Zhu, D., Hill, A. D. etal. 2007. Prediction of Temperature Changes Caused by Water or Gas Entryinto a Horizontal Well. SPE Prod & Oper 22(4): 425-433. SPE-100209-PA.https://doi.org/10.2118/100209-PA; Agnew, B. G. (1966). Evaluation offracture treatments with temperature surveys. Journal of PetroleumTechnology, 18(07), 892-898. https://doi.org/10.2118/1287-PA; Davis, E.R., Zhu, D., and Hill, A. D. 1997. Interpretation of Fracture Heightfrom Temperature Logs—The Effect of Wellbore/Fracture Separation. SPEForm Eval 12 (2): 119-124. SPE-29588-PA.https://doi.org/10.2118/29588-PA; and Li, X., & Zhu, D. (2018).Temperature Behavior During Multistage Fracture Treatments in HorizontalWells. SPE Production & Operations, 33(03), 522-538. SPE-181876-PAhttps://doi.org/10.2118/181876-PA, each incorporated herein by referencein their entirety. Analytical models have been developed to estimate thefluid temperature in the wellbore. See Ramey, H. J. 1962. Wellbore HeatTransmission. J Pet Technol 14 (4): 427-435. SPE-96-PA.https://doi.org/10.2118/96-PA, incorporated herein by reference in itsentirety. Analytical models have also been developed to simulate thereservoir temperature. See Terrill, R. M. 1965. Heat Transfer in LaminarFlow Between Parallel Porous Plates. International Journal of Heat andMass Transfer 8(12): 1491-1497.https://doi.org/10.1016/0017-9310(65)90034-7; and Whitsitt, N. F. andDysart, G. R. 1969. Effect of Temperature on Stimulation Design. PaperSPE 2497 presented at the Annual Fall Meeting of the Society ofPetroleum Engineers of AIME, Denver, Colo., 28 September-1 October.SPE-2497-MS. https://doi.org/10.2118/2497-MS, each incorporated hereinby reference in their entirety. Even though methods of estimating fluidtemperature and methods of estimating reservoir temperature are useful,sophisticated models are required when addressing complex scenarios. SeeYoshida, N., Hill, A. D., & Zhu, D. (2018). Comprehensive Modeling ofDownhole Temperature in a Horizontal Well with Multiple Fractures. SPEJournal 23(05): 1580-1602. SPE-181812-PA.https://doi.org/10.2118/181812-PA, incorporated herein by reference inits entirety. Reservoir temperature modelling can be used to evaluateinjected fluid rheology within a reservoir, formation cool down, acidreactivity, and temperature of produced fluids. Subsurface modelling canalso be used to investigate the possibility of condensate accumulationas in the method of the present disclosure.

When utilizing solar panels for increasing the temperature around awellbore, the solar panel design needs to be evaluated in order togenerate the energy that results in the increase of temperature. Inparticular, a temperature needs to be high enough to avoid the formationof condensate banks that would form naturally due to near wellborepressure drop. To fulfill the requirement, the metal section, which isthe heat conducting element, may be positioned to perimetricallysurround the wellbore. In another embodiment, the heat conductingelement may be positioned within the wellbore. Thus, a constant sourceof heat is active during gas production. Moreover, a reservoir pressureand a reservoir temperature should be modelled to investigate if the gasremains above a dew point as the gas enters the wellbore.

A pressure profile may be generated by solving a diffusivity equationfor compressible fluids. Generally, the pressure profile is obtained bysubstituting Darcy's law in the continuity equation in porous media.When gas is produced, near wellbore turbulence is likely to occur due tohigh gas velocity. Therefore, Forchheimer law is used instead torepresent the turbulence, which is a non-Darcy flow. A pressure drop andfluid velocity can be represented by Forchheimer law with equation 7.

$\begin{matrix}{{{- \text{∇}}p} = {{\frac{\mu}{k}u} + {\beta\rho u^{2}}}} & (7)\end{matrix}$Where:p—fluid pressure;k—permeability;ρ—density;u—velocity;β—Non-Darcy flow coefficient;As seen in equation 8, equation 7 can be rearranged to replicate Darcy'slaw:

$\begin{matrix}{{{- \text{∇}}p} = {\frac{\mu}{k_{nD}}u}} & (8)\end{matrix}$Where:k_(nD)—Non-Darcy permeability, wherein the non-Darcy permeability can beestimated using equation 9.

$\begin{matrix}{k_{nD} = \frac{k}{1 + N_{{Re},{nD}}}} & (9)\end{matrix}$

Where:

N_(Re,nD)—Non-Darcy Reynold number that can be expressed as:

$\begin{matrix}{N_{{Re},{nD}} = \frac{\beta k\rho u}{\mu}} & (10)\end{matrix}$According to the studies from Lee and Wattenbarger, the diffusivityequation in (11) radial form for compressible fluids can be representedas (see Lee, W. J. and Wattenbarger, R. A. 1996. Gas ReservoirEngineering, 5. Richardson, Tex.: Textbook Series, SPE):

${\frac{1}{r}\frac{\partial}{\partial r}( {{rk}_{nD}\frac{\partial{m(p)}}{\partial r}} )} = {{\varphi\mu}\; c_{t}\frac{\partial{m(p)}}{\partial t}}$Where:m(p)—pseudopressure function;φ—formation porosity;c_(t)—total compressibility;r—radial direction;t—time;Moreover, the pseudo pressure function can be expressed as in equation12.

$\begin{matrix}{{m(p)} = {2{\int_{p_{b}}^{p}{\frac{p}{\mu z}{dp}}}}} & (12)\end{matrix}$To solve the partial differential equation of equation 11, the pressureis equated to the initial reservoir pressure before production starts.Moreover, a constant flow rate is assumed at the inner boundarycondition, generating a Neumann boundary:

$\begin{matrix}{( {\text{∇}p} )_{wellbore} = {- \frac{q_{sc}B_{g}\mu}{2\pi r_{w}h_{pay}k_{nD}}}} & (13)\end{matrix}$Where:q_(sc)—Production rate at standard conditions;B_(g)—Gas formation volume factor;r_(w)—Wellbore radius;h_(pay)—Pay zone thickness;In deriving equation 13, a flow outer boundary condition is notimplemented and can be expressed as:n·∇p=0  (14)Where:N—normal vector to the boundary;

Gas compressibility factor is estimated by solving for the reduced gasdensity, ρ_(r), which is shown in equation 15.

$\begin{matrix}{{{R_{1}\rho_{r}} - \frac{R_{2}}{\rho_{r}} + {R_{3}\rho_{r}^{2}} - {R_{4}\rho_{r}^{5}} + {{R_{5}( {1 + {A_{11}\rho_{r}^{2}}} )}\rho_{r}^{2}e^{{- A_{11}}\rho_{r}^{2}}}} = 0} & (15)\end{matrix}$Where:R₁, R₂, R₃, R₄, and R₅—functions of pseudo-reduced temperature, T_(pr),and pseudo-reduced temperature P_(pr);A₁₁—Constant;Thus, the gas compressibility, Z, can be evaluated from the definitionof reduced gas density:ρ_(r)=0.27P _(pr) /ZT _(pr)  (16)Gas viscosity, which is pressure and temperature dependent, is estimatedusing the method given by equation 17.

$\begin{matrix}{{\mu = {10^{- 4}K\;{\exp\lbrack {X( \frac{\rho_{g}}{6{2.4}} )}^{Y} \rbrack}}}{{Where}:}} & (17) \\{K = \frac{( {{9.4} + {{0.0}2M_{a}}} )T^{1.5}}{{209} + {19M_{a}} + T}} & (18) \\{X = {{3.5} + \frac{986}{T} + {{0.0}1M_{a}}}} & (19) \\{Y = {{2.4} - {{0.2}X}}} & (20) \\{\rho_{g} = \frac{{pM}_{a}}{ZRT}} & (21) \\{M_{a} = {\sum\limits_{i = 1}^{n}M_{i}}} & (22)\end{matrix}$Where:T—Temperature,R—Universal gas constant;ρ_(g)—Gas density;M_(a)—Apparent molecular weight;M_(i)—Component molecular weight;n—Number of components;The total compressibility can be assumed to be equal to the gascompressibility, c_(g), wherein equation 22 is a representation ofc_(g).

$\begin{matrix}{c_{g} = {\frac{1}{p} - {\frac{1}{Z}( \frac{\partial Z}{\partial p} )_{T}}}} & (23)\end{matrix}$The temperature profile can be solved by obtaining the pressure andvelocity distributions. To do so, the energy balance equation is solvedassuming one dimensional (1-D) heat transfer. (Li and Zhu 2018).

$\begin{matrix}{{{\overset{\_}{\rho{\overset{\hat{}}{C}}_{p}}\frac{\partial T}{\partial t}} - {{\varphi\beta}_{T}T\frac{\partial p}{\partial t}} + {\rho_{g}{\overset{\hat{}}{C}}_{pg}u\frac{\partial T}{\partial r}}} = {{\frac{1}{r}\frac{\partial}{\partial r}( {\overset{¯}{\kappa}r\frac{\partial T}{\partial r}} )} + {( {{\beta_{T}T} - 1} )u\frac{\partial p}{\partial r}}}} & (24)\end{matrix}$Where:κ=φκ_(g)+(1−φ)κ_(r)  (25)β_(T)—Thermal expansion factor;Ĉ_(p)—Specific heat capacity;κ—Thermal conductivity;g—Representation for gas;r—Representation for rock;In equation 24, the heat accumulation is represented by

$\overset{\_}{\rho{\overset{\hat{}}{C}}_{p}}\frac{\partial T}{\partial t}\mspace{14mu}{and}\mspace{14mu}\varphi\;\beta_{T}T{\frac{\partial p}{\partial t}.}$The heat accumulation is represented by

$\rho_{g}{\overset{\hat{}}{C}}_{pg}u{\frac{\partial T}{\partial r}.}$The gas expansion effect is represented by

$( {{\beta_{T}T} - 1} )u{\frac{\partial p}{\partial r}.}$The differential equation is solved by applying the initial and boundaryconditions. Initially, the temperature is equal to the reservoirtemperature. An outer boundary temperature is assumed to be constant atreservoir temperature. The inner boundary condition can be specified as:

$\begin{matrix}{ {\overset{¯}{\kappa}\frac{\partial T}{\partial r}} |_{w} = {U( {T_{e} - {T\text{|}_{w}}} )}} & (26)\end{matrix}$Where:U—Overall heat transfer coefficient;T_(e)—Element temperature;w—Representation of the wellbore;The system of mass and heat equations are solved together to givemapping of pressure and temperature distributions in the reservoir.

As described earlier, in a different embodiment, wind energy maybe usedas the at least one renewable energy source. If wind energy is used asthe at least one renewable energy source, a wind turbine may be used toconvert wind energy into thermal energy directly using a heat generatorbased on the principle of the Joule machine. A heat generator based onthis principle is a mixer installed into a tank filled with a heattransfer agent (liquid). The shaft of a mixer is rotated by a windturbine and the liquid is mixed by an impeller. Due to friction amongmolecules of the mixing liquid, mechanical energy is converted into heatenergy. The heated liquid then transfers heat to a heating system.

The efficiency of the system wind turbine—heat generator assemblydepends on speed-torque characteristics of both elements of the system.The optimum performance of the system can be achieved when thespeed-torque characteristic of a wind turbine operating at maximum powercondition matches the characteristics of the heat generator.

For example, a wind turbine of the Savonius type, which is a verticalaxis wind turbine, may be used in one embodiment. These wind turbinesoperate at a low speed that does not exceed a tip speed ratio (TSR). Theamount of mechanical power produced by a wind turbine depends on thewind speed and the turbine parameters. In particular, the mechanicalpower produced by the wind turbine depends on the air density, powercoefficient, wind speed, turbine blade area, turbine radius, and heightof turbine rotor.

Generally, the heat generator includes a tank covered by thermalinsulation, an impeller and a shaft connected to the wind turbine. Theimpeller is rotated by the wind turbine and the tank is filled with theheat transfer liquid. The power generated by the wind turbine depends ona density of the heat transfer liquid, an impeller diameter, a gravityconstant, and a speed of the mixer shaft. Additionally, the power isalso a function of the number of blades, the impeller blade width, widthto diameter ratio, number of baffles, and the width of each of thebaffles. Water is preferably chosen as a heat transfer agent.

In a different embodiment, the wind turbine can be connected to agenerator that produces electricity. The electricity can then be used togenerate heat at the wellbore. Different types of wind turbines that canbe, but are not limited to, horizontal axis, vertical axis, and ductedwind turbines may be used in different embodiments.

In a horizontal axis wind turbine, the blades, the shaft, and thegenerator are on top of a tall tower, and the blades face into the wind.The shaft is horizontal to the ground. The wind hits the blades of theturbine that are connected to a shaft causing rotation. The shaft has agear on the end which turns a generator. The generator produceselectricity and sends the electricity into the power grid. The windturbine also has some key elements that adds to efficiency. Inside ahead of the wind turbine is an anemometer, wind vane, and controllerthat read the speed and direction of the wind. As the wind changesdirection, a motor (yaw motor) turns the nacelle so the blades arealways facing the wind. The power source also comes with a safetyfeature. In case of extreme winds the turbine has a break that can slowthe shaft speed. To inhibit any damage to the turbine in extremeconditions.

In vertical axis turbines, the shaft the blades are connected to isvertical to the ground. The blades, the shaft, and the generator arepositioned closer to the ground and the overall assembly of the verticalaxis turbine is closer to the ground. The vertical axis wind turbinescan be categorized as lift based and drag based.

Ducted wind turbines are generally positioned at the edge of a roof of abuilding and utilize the airflow along a side of the building. The airflows upwards, hugging the building wall then enters the front of theduct. Turbine blade diameter is usually around 600 mm.

Next, a hardware description of the phase diagram plotting moduleaccording to exemplary embodiments is described with reference to FIG.13. In FIG. 13, the phase diagram plotting module includes a CPU 100which performs the processes described above/below. The process data andinstructions may be stored in memory 102. These processes andinstructions may also be stored on a storage medium disk 104 such as ahard drive (HDD) or portable storage medium or may be stored remotely.Further, the claimed advancements are not limited by the form of thecomputer-readable media on which the instructions of the inventiveprocess are stored. For example, the instructions may be stored on CDs,DVDs, in FLASH memory, RAM, ROM, PROM, EPROM, EEPROM, hard disk or anyother information processing device with which the phase diagramplotting module communicates, such as a server or computer.

Further, the claimed advancements may be provided as a utilityapplication, background daemon, or component of an operating system, orcombination thereof, executing in conjunction with CPU 100 and anoperating system such as Microsoft Windows 7, UNIX, Solaris, LINUX,Apple MAC-OS and other systems known to those skilled in the art.

The hardware elements in order to achieve the phase diagram plottingmodule may be realized by various circuitry elements, known to thoseskilled in the art. For example, CPU 100 may be a Xenon or Coreprocessor from Intel of America or an Opteron processor from AMD ofAmerica, or may be other processor types that would be recognized by oneof ordinary skill in the art. Alternatively, the CPU 100 may beimplemented on an FPGA, ASIC, PLD or using discrete logic circuits, asone of ordinary skill in the art would recognize. Further, CPU 100 maybe implemented as multiple processors cooperatively working in parallelto perform the instructions of the inventive processes described above.

The phase diagram plotting module in FIG. 13 also includes a networkcontroller 106, such as an Intel Ethernet PRO network interface cardfrom Intel Corporation of America, for interfacing with network 11. Ascan be appreciated, the network 11 can be a public network, such as theInternet, or a private network such as an LAN or WAN network, or anycombination thereof and can also include PSTN or ISDN sub-networks. Thenetwork 11 can also be wired, such as an Ethernet network, or can bewireless such as a cellular network including EDGE, 3G and 4G wirelesscellular systems. The wireless network can also be WiFi, Bluetooth, orany other wireless form of communication that is known.

The phase diagram plotting module further includes a display controller108, such as a NVIDIA GeForce GTX or Quadro graphics adaptor from NVIDIACorporation of America for interfacing with display 110, such as aHewlett Packard HPL2445w LCD monitor. A general purpose I/O interface112 interfaces with a keyboard and/or mouse 114 as well as a touchscreen panel 116 on or separate from display 110. General purpose I/Ointerface also connects to a variety of peripherals 118 includingprinters and scanners, such as an OfficeJet or DeskJet from HewlettPackard.

A sound controller 120 is also provided in the phase diagram plottingmodule, such as Sound Blaster X-Fi Titanium from Creative, to interfacewith speakers/microphone 122 thereby providing sounds and/or music.

The general purpose storage controller 124 connects the storage mediumdisk 104 with communication bus 126, which may be an ISA, EISA, VESA,PCI, or similar, for interconnecting all of the components of the phasediagram plotting module. A description of the general features andfunctionality of the display 110, keyboard and/or mouse 114, as well asthe display controller 108, storage controller 124, network controller106, sound controller 120, and general purpose I/O interface 112 isomitted herein for brevity as these features are known.

The exemplary circuit elements described in the context of the presentdisclosure may be replaced with other elements and structureddifferently than the examples provided herein. Moreover, circuitryconfigured to perform features described herein may be implemented inmultiple circuit units (e.g., chips), or the features may be combined incircuitry on a single chipset, as shown on FIG. 14.

FIG. 14 shows a schematic diagram of a data processing system, accordingto certain embodiments, for plotting the phase diagram. The dataprocessing system is an example of a computer in which code orinstructions implementing the processes of the illustrative embodimentsmay be located.

In FIG. 14, data processing system 200 employs a hub architectureincluding a north bridge and memory controller hub (NB/MCH) 225 and asouth bridge and input/output (I/O) controller hub (SB/ICH) 220. Thecentral processing unit (CPU) 230 is connected to NB/MCH 225. The NB/MCH225 also connects to the memory 245 via a memory bus, and connects tothe graphics processor 250 via an accelerated graphics port (AGP). TheNB/MCH 225 also connects to the SB/ICH 220 via an internal bus (e.g., aunified media interface or a direct media interface). The CPU Processingunit 230 may contain one or more processors and even may be implementedusing one or more heterogeneous processor systems.

For example, FIG. 15 shows one implementation of CPU 230. In oneimplementation, the instruction register 338 retrieves instructions fromthe fast memory 340. At least part of these instructions are fetchedfrom the instruction register 338 by the control logic 336 andinterpreted according to the instruction set architecture of the CPU230. Part of the instructions can also be directed to the register 332.In one implementation the instructions are decoded according to ahardwired method, and in another implementation the instructions aredecoded according a microprogram that translates instructions into setsof CPU configuration signals that are applied sequentially over multipleclock pulses. After fetching and decoding the instructions, theinstructions are executed using the arithmetic logic unit (ALU) 334 thatloads values from the register 332 and performs logical and mathematicaloperations on the loaded values according to the instructions. Theresults from these operations can be feedback into the register and/orstored in the fast memory 340. According to certain implementations, theinstruction set architecture of the CPU 230 can use a reducedinstruction set architecture, a complex instruction set architecture, avector processor architecture, a very large instruction wordarchitecture. Furthermore, the CPU 230 can be based on the Von Neumanmodel or the Harvard model. The CPU 230 can be a digital signalprocessor, an FPGA, an ASIC, a PLA, a PLD, or a CPLD. Further, the CPU230 can be an x86 processor by Intel or by AMD; an ARM processor, aPower architecture processor by, e.g., IBM; a SPARC architectureprocessor by Sun Microsystems or by Oracle; or other known CPUarchitecture.

Referring again to FIG. 14, the data processing system 200 can includethat the SB/ICH 220 is coupled through a system bus to an I/O Bus, aread only memory (ROM) 256, universal serial bus (USB) port 264, a flashbinary input/output system (BIOS) 268, and a graphics controller 258.PCI/PCIe devices can also be coupled to SB/ICH 220 through a PCI bus262.

The PCI devices may include, for example, Ethernet adapters, add-incards, and PC cards for notebook computers. The Hard disk drive 260 andCD-ROM 266 can use, for example, an integrated drive electronics (IDE)or serial advanced technology attachment (SATA) interface. In oneimplementation the I/O bus can include a super I/O (SIO) device.

Further, the hard disk drive (HDD) 260 and optical drive 266 can also becoupled to the SB/ICH 220 through a system bus. In one implementation, akeyboard 270, a mouse 272, a parallel port 278, and a serial port 276can be connected to the system bust through the I/O bus. Otherperipherals and devices that can be connected to the SB/ICH 220 using amass storage controller such as SATA or PATA, an Ethernet port, an ISAbus, a LPC bridge, SMBus, a DMA controller, and an Audio Codec.

Moreover, the present disclosure is not limited to the specific circuitelements described herein, nor is the present disclosure limited to thespecific sizing and classification of these elements. For example, theskilled artisan will appreciate that the circuitry described herein maybe adapted based on changes on battery sizing and chemistry, or based onthe requirements of the intended back-up load to be powered.

The functions and features described herein may also be executed byvarious distributed components of a system. For example, one or moreprocessors may execute these system functions, wherein the processorsare distributed across multiple components communicating in a network.The distributed components may include one or more client and servermachines, which may share processing, as shown on FIG. 16, in additionto various human interface and communication devices (e.g., displaymonitors, smart phones, tablets, personal digital assistants (PDAs)).The network may be a private network, such as a LAN or WAN, or may be apublic network, such as the Internet. Input to the system may bereceived via direct user input and received remotely either in real-timeor as a batch process. Additionally, some implementations may beperformed on modules or hardware not identical to those described.Accordingly, other implementations are within the scope that may beclaimed.

The above-described hardware description is a non-limiting example ofcorresponding structure for performing the functionality describedherein.

Terminology used herein is for the purpose of describing particularembodiments only and is not intended to be limiting of the invention.

As used herein, the singular forms “a”, “an” and “the” are intended toinclude the plural forms as well, unless the context clearly indicatesotherwise.

It will be further understood that the terms “comprises” and/or“comprising,” when used in this specification, specify the presence ofstated features, steps, operations, elements, and/or components, but donot preclude the presence or addition of one or more other features,steps, operations, elements, components, and/or groups thereof.

As used herein, the term “and/or” includes any and all combinations ofone or more of the associated listed items and may be abbreviated as“/”.

As used herein in the specification and claims, including as used in theexamples and unless otherwise expressly specified, all numbers may beread as if prefaced by the word “substantially”, “about” or“approximately,” even if the term does not expressly appear. The phrase“about” or “approximately” may be used when describing magnitude and/orposition to indicate that the value and/or position described is withina reasonable expected range of values and/or positions. For example, anumeric value may have a value that is +/−0.1% of the stated value (orrange of values), +/−1% of the stated value (or range of values), +/−2%of the stated value (or range of values), +/−5% of the stated value (orrange of values), +/−10% of the stated value (or range of values),+/−15% of the stated value (or range of values), +/−20% of the statedvalue (or range of values), etc. Any numerical range recited herein isintended to include all subranges subsumed therein.

Disclosure of values and ranges of values for specific parameters (suchas temperatures, molecular weights, weight percentages, etc.) are notexclusive of other values and ranges of values useful herein. It isenvisioned that two or more specific exemplified values for a givenparameter may define endpoints for a range of values that may be claimedfor the parameter. For example, if Parameter X is exemplified herein tohave value A and also exemplified to have value Z, it is envisioned thatparameter X may have a range of values from about A to about Z.Similarly, it is envisioned that disclosure of two or more ranges ofvalues for a parameter (whether such ranges are nested, overlapping ordistinct) subsume all possible combination of ranges for the value thatmight be claimed using endpoints of the disclosed ranges. For example,if parameter X is exemplified herein to have values in the range of 1-10it also describes subranges for Parameter X including 1-9, 1-8, 1-7,2-9, 2-8, 2-7, 3-9, 3-8, 3-7, 2-8, 3-7, 4-6, or 7-10, 8-10 or 9-10 asmere examples. A range encompasses its endpoints as well as valuesinside of an endpoint, for example, the range 0-5 includes 0, >0, 1, 2,3, 4, <5 and 5.

As used herein, the words “preferred” and “preferably” refer toembodiments of the technology that afford certain benefits, undercertain circumstances. However, other embodiments may also be preferred,under the same or other circumstances. Furthermore, the recitation ofone or more preferred embodiments does not imply that other embodimentsare not useful, and is not intended to exclude other embodiments fromthe scope of the technology.

Spatially relative terms, such as “under”, “below”, “lower”, “over”,“upper”, “in front of” or “behind” and the like, may be used herein forease of description to describe one element or feature's relationship toanother element(s) or feature(s) as illustrated in the figures. It willbe understood that the spatially relative terms are intended toencompass different orientations of is the device in use or operation inaddition to the orientation depicted in the figures. For example, if adevice in the figures is inverted, elements described as “under” or“beneath” other elements or features would then be oriented “over” theother elements or features. Thus, the exemplary term “under” canencompass both an orientation of over and under. The device may beotherwise oriented (rotated 90 degrees or at other orientations) and thespatially relative descriptors used herein interpreted accordingly.Similarly, the terms “upwardly”, “downwardly”, “vertical”, “horizontal”and the like are used herein for the purpose of explanation only unlessspecifically indicated otherwise.

The description and specific examples, while indicating embodiments ofthe technology, are intended for purposes of illustration only and arenot intended to limit the scope of the technology. Moreover, recitationof multiple embodiments having stated features is not intended toexclude other embodiments having additional features, or otherembodiments incorporating different combinations of the stated features.Specific examples are provided for illustrative purposes of how to makeand use the compositions and methods of this technology and, unlessexplicitly stated otherwise, are not intended to be a representationthat given embodiments of this technology have, or have not, been madeor tested.

The citation of references herein does not constitute an admission thatthose references are prior art or have any relevance to thepatentability of the technology disclosed herein. Any discussion of thecontent of references cited is intended merely to provide a generalsummary of assertions made by the authors of the references, and doesnot constitute an admission as to the accuracy of the content of suchreferences.

Obviously, numerous modifications and variations of the presentinvention are possible in light of the above teachings. It is thereforeto be understood that within the scope of the appended claims, theinvention may be practiced otherwise than as specifically describedherein.

The invention claimed is:
 1. A method of recovering natural gas from asubterranean hydrocarbon reservoir, comprising: applying an electricalcurrent to a liquid condensation prevention system to heat a heatconducting element, wherein the electrical current is generated from atleast one renewable energy source, wherein the liquid condensationprevention system comprising: the heat conducting element beingpositioned within a wellbore located in the subterranean hydrocarbonreservoir, wherein the heat conducting element is connected to aproduction tubing having a producing end disposed in the subterraneanhydrocarbon reservoir and a recovery end located outside the wellbore,and wherein the production tubing is configured to pass gaseous naturalgas from the producing end of the production tubing in the subterraneanhydrocarbon reservoir to the recovery end of the production tubingoutside the wellbore; the heat conducting element being electricallycoupled with the at least one renewable energy source; the heatconducting element being in thermal communication with the subterraneanhydrocarbon reservoir; applying the electrical current such that atemperature of the subterranean hydrocarbon reservoir at the producingend of the tubing remains above a cricondentherm temperature of thenatural gas; monitoring a production rate of the subterraneanhydrocarbon reservoir to identify a final production time, wherein theproduction rate matches a predetermined production rate at the finalproduction; adjusting the temperature ofth.e subterranean hydrocarbonreservoir at the producing end to prevent liquid condensation at thefinal production time by adjusting the electrical current from the atleast one renewable energy source; recovering the natural gas from thesubterranean hydrocarbon reservoir, and detecting liquid condensationby: recording an internal temperature and an internal pressure of thesubterranean hydrocarbon reservoir at each time step of a plurality oftime steps; and plotting a phase diagram using the internal temperatureand the internal pressure for each of the plurality of time steps up toa dew point using an equation of state, wherein the equation of state isa cubic-plus-association (CPA).
 2. The method of recoveting natural gasfrom a subterranean hydrocarbon reservoir as of claim 1, wherein thetemperature of the subterranean hydrocarbon reservoir at the producingend is above the cricondentherm temperature of the natural gas by atemperature within a range of 100 Fahrenheit (° F.)-150° F.
 3. Themethod of recovering natural gas from a subterranean hydrocarbonreservoir as of claim I. wherein the at least one renewable energysource is solar energy, wherein a surface area of a solar cell used ingenerating solar energy is proportional to a production rate of thesubterranean hydrocarbon reservoir.
 4. The method of recovering naturalgas from a subterranean hydrocarbon reservoir as of claim 1, wherein theat least one renewable energy source is solar energy, wherein a surfacearea of a solar cell used in generating solar energy is proportional tothe temperature of the subterranean hydrocarbon reservoir at theproducing end.
 5. The method of recovering natural gas from asubterranean Hydrocarbon reservoir as of claim 1, wherein the finalproduction time is within a range of 1000 hours-1500 hours.
 6. Themethod of recovering natural gas from a subterranean hydrocarbonreservoir as of claim 1, wherein a measured wellbore pressure value atthe final production time is approximately half of an initial wellborepressure value, wherein the measured wellbore pressure value and theinitial wellbore pressure value are measured within the wellbore.
 7. Themethod of recovering natural gas from a subterranean hydrocarbonreservoir as of claim 1, wherein the cricondentherm temperature can beachieved up to a distance within a range of 0.5 feet (ft)-2.5 ft fromthe wellbore during a subterranean hydrocarbon reservoir shut-in.
 8. Themethod of recovering natural gas from a subterranean hydrocarbonreservoir as of claim 1, wherein the heat conducting element is a metalsection perimetrically surrounding the wellbore.
 9. The method ofrecovering natural gas from a subterranean hydrocarbon reservoir as ofclaim 1, wherein the at least one renewable energy source is windenergy.
 10. The method of recovering natural gas from a subterraneanhydrocarbon reservoir as of claim 1, wherein the heat conducting elementis a current transformer, comprising: a primary winding; a secondarywinding; the primary winding being electrically coupled with thesecondary winding, wherein the electrical current applied to the primarywinding induces a proportional electrical current at the secondarywinding which is positioned adjacent the producing end of the productiontubing; and the secondary winding being in thermal communication withthe subterranean hydrocarbon reservoir, wherein heat generated at thesecondary winding from the proportional electrical current istransferred to the subterranean hydrocarbon reservoir via conduction.11. The method of recovering natural gas from a subterranean hydrocarbonreservoir as of claim 1, wherein the subterranean hydrocarbon reservoiris heated via electromagnetic heating: the heat conducting element is aconducting surface magnetically coupled with at least one magnet,comprising: inducing eddy currents on the conducting surface by changinga magnetic field. applied to the conducting surface, wherein themagnetic field is changed via relative motion between the at least onemagnet and the conducting surface; and dissipating heat into thesubterranean hydrocarbon reservoir, wherein the eddy currents flowingthrough a resistance of the conducting surface generates heat.
 12. Themethod of recovering natural gas from a subterranean hydrocarbonreservoir as of claim 1, wherein the heat conducting element is at leastone electric heating cable vertically suspended into the wellbore.